Drivers and implications of alternative routes to fuels decarbonization in net-zero energy systems

Energy transition scenarios are characterized by increasing electrification and improving efficiency of energy end uses, rapid decarbonization of the electric power sector, and deployment of carbon dioxide removal (CDR) technologies to offset remaining emissions. Although hydrocarbon fuels typically decline in such scenarios, significant volumes remain in many scenarios even at the time of net-zero emissions. While scenarios rely on different approaches for decarbonizing remaining fuels, the underlying drivers for these differences are unclear. Here we develop several illustrative net-zero systems in a simple structural energy model and show that, for a given set of final energy demands, assumptions about the use of biomass and CO2 sequestration drive key differences in how emissions from remaining fuels are mitigated. Limiting one resource may increase reliance on another, implying that decisions about using or restricting resources in pursuit of net-zero objectives could have significant tradeoffs that will need to be evaluated and managed.

. The other IPCC cases are median outcomes for all C1 scenarios in which carbon dioxide removal (CDR) is less than or greater than the stated percentile.Reporting of feedstock uses of energy in the IPCC database is sparse and therefore not included here.In the International Energy Agency (IEA) net-zero case [3], ammonia and non-energy use are subtracted from IEA reported liquid fuels, and hydrogen is subtracted from IEA reported gaseous fuels.In the Open Energy Outlook (OEO) cases [4], for the purpose of this table, realized net energy CO2 is estimated by subtracting industrial process emissions, land CO2 and non-CO2 emissions (estimated from known lifecycle coefficients of fuels) from net GHG emissions (assumed to be zero).The core case is the single deterministic net-zero case, and the low and high bio cases are cases with total bioenergy with carbon capture and sequestration (BECCS) deployment equal to the 10 th percentile and the 90 th percentile, respectively, from the larger scenario ensemble using the modeling-to-generate-alternatives (MGA) method.The three EPRI cases are the Limited Options, All Options, and Higher Fuel Cost cases from the EPRI Low-Carbon Resources Initiative (LCRI) net-zero 2050 study [5].Three (of six) cases are shown from Williams et al [6]: the Central Case, as well as the cases with the lowest and highest amounts of CDR (100% RE and Low Land cases, respectively).Realized net energy CO2 is estimated by subtracting industrial process emissions (known from the 100% RE case) from total energy and industrial emissions.In addition, potential CO2 emissions from fuels is estimated by subtracting product and bunker CO2 (reported as approximately 0.5 Gt) from the sum of B1 and B2.The allocation of fuels across different sources is estimated using the shares reported in Table 1 of Williams et al. [6].Across all studies and cases, for ease of comparison, the carbon intensities for oil and natural gas are assumed be the same (0.071 and 0.053 ton/GJ, respectively), which may introduce small errors.Natural gas coupled with CCS is generally not included because potential emissions will be small (assuming high capture fractions), but this may introduce small errors.Errors due to rounding may also explain some differences.Efficiency is defined with respect to the dominant energy input (e.g., biomass for Bio, natural gas for Gas, etc.).CFE refers to carbon-free electricity (wind, solar, nuclear, and hydro).CCS refers to carbon capture and sequestration.Capital costs are based on National Renewable Energy Laboratory (NREL) Annual Technology Baseline (ATB) 2022 [8].CFE is based on solar PV with an assumed capacity factor of 25%.Adjusting for differences in regional capacity factors, the CFE cost is comparable to the 2050 solar PV cost assumptions from the International Energy Agency (IEA) [9].Bio CCS is based on Bio with capital costs inflated using the cost difference between coal with CCS and coal without CCS.H2 is based on Gas with the primary difference being the cost of the fuel consumed (not shown here).Efficiency is defined with respect to the dominant energy input (e.g., biomass for Bio, natural gas for Gas, etc.).CCS refers to carbon capture and sequestration.Capital costs for Gas, Gas CCS and Grid Electrolysis are based on longterm cost estimates from the International Energy Agency (IEA) [10].Bio and Bio CCS are based on coal gasification with and without CCS, respectively, from the same source.The resulting levelized non-energy costs for gas CCS, Bio CCS and electrolysis are comparable to the 2050 costs reported by O'Rourke et al [11], which were derived from the National Renewable Energy Laboratory (NREL) H2A [12] assumptions.The costs for Gas CCS are close to the total plant costs estimated by the National Energy Technology Laboratory (NETL) for an Nth-of-a-Kind steam methane reformer (SMR) with CCS assuming 96% capture, and the conversion efficiency is also comparable [13].
All costs are reported on an output basis ($/kW H2).

Liquid Fuel Production Technology
Non  [14].Assumptions for Synthetic FT are based on IEA [10].Non-energy costs for Bio FT are in the range of capital plus operating expenses shown in [15] and in Kreutz et al [16].Synthetic FT involves production of a synthetic fuel in which hydrogen and CO2 are used as inputs to an FT synthesis process.
The reported efficiency of this technology reflects the efficiency of hydrogen use.Following Zang et al. [17], it is assumed that the CO2 utilization efficiency is near 50%, or that ~7 GJ of fuel can be produced with 1 ton CO2.A significant share of the CO2 that is not utilized can be captured at an additional cost (Synthetic FT CCS) and utilized again or sequestered.The cost of the Synthetic FT CCS technology is based on the Synthetic FT technology with costs inflated using the difference between Bio FT CCS and Bio FT.All costs are reported on an output basis ($/GJ liquid fuel produced).

Natural Gas Production Technology
Non

Supplementary Figure 3 |Supplementary Figure 4 |Supplementary Figure 5 |
Results for cases in which the carbon intensities of oil, natural gas, and biomass are increased to reflect non-CO2 and land-related emissions.Panels (a), (b), (c) and (d) show production (by technology) and use (by sector and technology) of electricity, hydrogen, liquids, and natural gas in each of the four core cases.Panels (e) and (f) show biomass primary energy and captured CO2 (by source), respectively, along with their final dispositions.Panel (g) shows gross positive and negative CO2 emissions.Final energy does not vary across cases.Source data are provided as a Source Data File.Results for cases in which the constraint on carbon-free electricity is removed.Panels (a), (b), (c) and (d) show production (by technology) and use (by sector and technology) of electricity, hydrogen, liquids, and natural gas in each of the four core cases.Panels (e) and (f) show biomass primary energy and captured CO2 (by source), respectively, along with their final dispositions.Panel (g) shows gross positive and negative CO2 emissions.Final energy does not vary across cases.Source data are provided as a Source Data File.Results for cases in which NG prices are higher and biomass prices are lower than default values.Panels (a), (b), (c) and (d) show production (by technology) and use (by sector and technology) of electricity, hydrogen, liquids, and natural gas in each of the four core cases.Panels (e) and (f) show biomass primary energy and captured CO2 (by source), respectively, along with their final dispositions.Panel (g) shows gross positive and negative CO2 emissions.Final energy does not vary across cases.Source data are provided as a Source Data File.

Supplementary Table 8 |Supplementary Table 9 | 3 . 3 .Supplementary Table 10 |
Values for the Unconstrained (UC) case in Figure 3. Positive values indicate production, whereas negative values indicate disposition, consistent with Figure 3. Values for the Biomass Constrained (BC) case in Figure Positive values indicate production, whereas negative values indicate disposition, consistent with Figure Values for the Sequestration Constrained (SC) case in Figure 3. Positive values indicate production, whereas negative values indicate disposition, consistent with Figure 3.

Table 1 | 2050 outcomes for key variables across published studies
. P50 results for Intergovernmental Panel on Climate Change (IPCC) are median outcomes from the C1 scenarios

Table 2 | Median and other percentiles for final energy demand by carrier in 2020 and 2050 in 1.5°C scenarios.
[1,7].5°C scenarios are the set of 97 (C1) scenarios assessed by the Intergovernmental Panel on Climate Change (IPCC) that are consistent with 1.5°C stabilization with limited or no overshoot[1,7].Values in each row are estimated separately based on the distribution for that variable.It is worth noting that, due to the competition among these energy carriers, the set of outcomes in each column is not likely to occur within any actual scenario (e.g., scenarios with P10 outcomes for liquid fuels are likely to have electricity outcomes considerably higher than P10).

Supplementary Table 5 | Costs and conversion efficiencies for liquid fuel production technologies in the simple model
. Efficiency is defined with respect to the dominant energy input (e.g., biomass for Bio FT, hydrogen for Synthetic FT, etc.).Non-energy cost includes capital and operating costs but not feedstock costs.CCS refers to carbon capture and sequestration.FT refers to Fischer-Tropsch processes.Assumptions for Conventional, Bio FT and Bio FT CCS follow Muratori et al.

Table 6 | Costs and conversion efficiencies for natural gas production technologies in the simple model.
[10]ciency is defined with respect to the dominant energy input (e.g., biomass for Bio, hydrogen for Synthetic, etc.).Non-energy cost includes capital and operating costs but not feedstock costs.For conventional (fossil) natural gas, the costs and losses associated with processing are assumed to be small relative to the cost of the fuel.CCS refers to carbon capture and sequestration.Assumptions for Bio follow[15], and assumptions for synthetic gas from methanation are based on[10].It is assumed that the CO2 utilization efficiency for synthetic methane is 90%.All costs are reported on an output basis ($/GJ natural gas produced).

Table 7 | Median and other percentiles for key outcomes in 2020 and 2050 in 1.5°C scenarios
[1,7] 1.5°C scenarios are the set of 97 (C1) scenarios assessed by the Intergovernmental Panel on Climate Change (IPCC) that are consistent with 1.5°C stabilization with limited or no overshoot[1,7].Values in each row are estimated separately based on the distribution for that variable.CFE share is the carbon-free share in electricity, where carbon-free is defined as wind, solar, nuclear, and hydro.LE share is the low-emission share, which includes the four technologies in the CFE share, as well as carbon capture and sequestration (CCS) technologies.Primary bio is the amount of modern biomass primary energy, and CO2 seq is the amount of geologic CO2 sequestration per year.

Table 11 | Values for the Sequestration and Biomass Constrained (SBC) case in Figure 3.
Positive values indicate production, whereas negative values indicate disposition, consistent with Figure 3.

Table 13 | Core scenarios and sensitivity scenarios considered in this study.
[18]]inal demands are 2050 values from the C1 scenarios in the Intergovernmental Panel on Climate Change (IPCC) AR6 scenarios database[1,7].Default assumptions are median values from the full set of C1 scenarios (Median C1), while the Lower Final Demand cases use median values from the subset of C1 scenarios in which total final demand is less than the 25 th percentile (339 EJ), close to the 10 th percentile of all C1 cases.Final demands for electricity, hydrogen, liquids, natural gas, and biomass in this case are 176, 11, 64, 29 and 20 EJ, respectively.The addition to the carbon intensity in the Higher Fossil & Bio CI cases are 0.006, 0.014 and 0.020 tons per GJ for oil, natural gas, and biomass, respectively, following DeCarolis et al.[18]and discussed in Methods.The default carbon-free electricity (CFE) share (91%) is discussed in Methods.The cases with alternative fuel prices use $15 per GJ for natural gas and $5 per GJ for biomass, compared with default values of $6 per GJ (natural gas) and $10 per GJ (biomass), as discussed in Methods.Cases with higher bioenergy with carbon capture and sequestration (BECCS) costs increase non-energy costs of BECCS electricity and BECCS H2 by 50% relative to the core cases.